1. Field of the Invention
The present invention relates to methods and apparatus for making in situ determinations regarding hydrocarbon bearing geological formations. The present invention more particularly relates to methods and apparatus for conducting phase calculations on samples of downhole fluids. The phase calculations may then be used in order to determine the proximity of the parameters of the formation to one or more of a vapor pressure line, a bubble point curve, a dew point curve, and a critical point for the fluid. The invention has application to downhole testing procedures and to production parameters and procedures, although it is not limited thereto.
2. State of the Art
Characterizing commercially viable accumulations of hydrocarbons is the main objective of well logging. Downhole sampling and testing tools such as the Modular Dynamic Formation Tester (MDT) (MDT being a trademark of Schlumberger Ltd.) are used during the logging phase to gain a more direct assessment of the production characteristics of the accumulation. The objective of the MDT tool is to provide a controlled channel of hydraulic communication between the reservoir fluid and the wellbore. The tool allows withdrawal of small amounts of formation fluid through a probe that contacts the reservoir rock (formation). In addition to obtaining a more direct measurement of the flow characteristics of the reservoir and the formation pressure, high quality samples of fluid can be obtained for analysis. Historically, the fluid samples were brought to the surface for analysis in the laboratory, but recent developments in the MDT tool have made possible the direct measurement of fluid properties downhole during the pump-out or sampling sequence. Details of the MDT tool and the Optical Fluid Analyzer (OFA) module of the MDT tool may be obtained with reference to commonly owned U.S. Pat. No. 3,859,851 to Urbanosky, U.S. Pat. No. 4,994,671 to Safinya et al., U.S. Pat. No. 5,167,149 to Mullins et al., U.S. Pat. No. 5,201,220 to Mullins et al., U.S. Pat. No. 5,266,800 to Mullins et al., and U.S. Pat. No. 5,331,156 to Hines et al., all of which are hereby incorporated by reference in their entireties herein.
The main advantage of downhole analysis is that the fluid is relatively pristine. If the sampling pressure is above the saturation pressure, the fluid will be in a single phase ensuring that the original composition is being analyzed. For pressures below the saturation pressure a measurement of the properties of the liquid phase in the oil zone and the associated gas above it will yield a more accurate sampling than a sample recombined in surface. Indeed, it may be difficult to retain the sample in the state in which it existed downhole when it is retrieved to surface.
Petroleum oil and gas are essentially a mixture of several hydrocarbon components whose variation dictates the characteristics of the fluid. Different types of reservoir fluids include black oils, volatile oils, retrograde condensates, wet gases, and dry gases, and the fluid types require different considerations for their exploitation, and different properties are used for their description. For example, it is generally agreed that black oils and dry gases can be described satisfactorily using averaged properties of the oil and gas phases, such as the volumetric factors and gas solubility ratios. Volatile oils, retrograde condensates and wet gases require a more detailed knowledge of the fluid composition since the ultimate recovery will be dictated by the control of the production conditions (mostly pressure).
A downhole fluid analysis provides information in real time in contrast to a laboratory analysis that may last for several days, or surface wellsite analysis, which may result in undesirable phase transitions as well as the loss of key constituents. One component that can be analyzed downhole is hydrogen sulfide (H2S). Although this component does not significantly affect the phase behavior of the reservoir fluids it is significant for metallurgy of the production string.
A detailed description of the fluid properties is desirable for an accurate modeling of the fluids in the reservoir. Indeed, decisions such as the type of well completion, production procedures and the design of the surface handling and processing facilities are affected by the characteristics of the produced fluids. For example, if fluid in the reservoir is a retrograde condensate, the saturation (dew) pressure, combined with the formation pressure and permeability will dictate the maximum pressure drawdown for production of the fluids, or whether an injection scheme for pressure maintenance or liquid vaporization should be implemented.